Passive cased well image logging

ABSTRACT

A method of creating a well image log of a cased well is provided. A passive cased well image logging tool assembly including a logging tool body, a plurality of gamma ray radiation sensors and a spatial positioning device is moved through at least a portion of the wellbore at a logging speed of no greater than 750 feet per hour. Corrected gamma ray radiation data is vertically sampled at a vertical distance sampling rate of once every vertical distance sampling interval, wherein the vertical distance sampling interval is no greater than 1.75 inches. Based on the sampled data, a well image log is prepared. A passive cased well image logging tool assembly for use in a cased well is also provided.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of prior-filed U.S. provisionalapplication No. 62/434,162 (filed on Dec. 14, 2016), which isincorporated by reference herein.

BACKGROUND

An oil and gas well is created by drilling a wellbore on a desiredsurface site that extends from the surface to a certain depth ordistance into the ground. The wellbore penetrates the underlying earthand various geologic units therein. With proper planning and placement,one or more of the geologic units penetrated by the wellbore willinclude commercial quantities of hydrocarbons such as oil and gas. Thewellbore can extend vertically, at an angle and/or horizontally throughthe earth. For various reasons, including rock and drillingheterogeneities, the actual direction of a wellbore tends to deviate atleast to some extent from the intended direction of the wellbore. Also,the diameter and roughness (or “rugosity”) of the resulting boreholetypically changes as the wellbore is drilled because of similar rock anddrilling heterogeneities.

As the wellbore is being drilled, a drilling fluid, also referred to asdrilling mud, is continuously circulated from the surface through thewellbore and back to the surface. The drilling fluid functions to removecuttings from the borehole, control formation pressure, and cool andlubricate the drill bit. After the wellbore is drilled to a certain ortarget depth, casing (typically metallic casing) is usually inserted andcemented in place in the now completed wellbore. The casing typicallyextends to the total depth (“TD”) of the wellbore. The casing isolatesand seals off various geologic zones that have been penetrated by thewellbore and serves multiple other purposes. Cement material is usuallyinjected around the casing and allowed to harden into an annular sheatharound the casing. The cement sheath physically supports, positions andprotects the casing in the wellbore and bonds the casing to the walls ofthe wellbore such that the undesirable migration of fluids between zonesor formations penetrated by the wellbore is prevented.

After the wellbore is drilled to the desired depth and cased, the wellis ready for the final completion and production phases. Finalcompletion of the well includes the creation of one or more accessconduits (for example, perforations) that extend through the casing andcement sheath to provide communication between the wellbore and one ormore of the geologic units from which hydrocarbons are to be produced.The casing and cement sheath provide a solid support for the accessconduits. Once the well is completed, the gas and/or fluids, which mayinclude hydrocarbons and water, are produced or allowed to flow from thenow completed geologic unit(s) into the wellbore and then to the surfacewhere they are processed for future use.

Numerous important procedures are typically carried out on a well duringthe well drilling phase and before the well completion phase. One ofthese procedures involves gathering geologic and engineering dataregarding the size and configuration of the borehole and the nature andcharacteristics of the surrounding geologic units. The collection ofsuch data, typically referred to as well logging or formation logging,can be performed by one of several downhole methods within the uncasedwellbore, including mud logging, wireline logging with a wireline cable,or using the bit assembly for measurement-while-drilling (“MWD”) orlogging-while-drilling (“LWD”) techniques. Various specialized loggingtools have been developed for use in connection with each method. Theparticular method and type of tools utilized will depend on severalfactors, including the borehole inclination and condition, costs andtime, and the type of geologic units penetrated by the wellbore.

In one downhole logging method, a logging tool is attached to the end ofa wireline cable and lowered to the desired depth in the wellbore (forexample, to the bottom of the wellbore) and then pulled back to thesurface at a set rate or speed (the “logging speed”). Data is collectedas the tool is pulled back to the surface and transmitted through thecable to the surface. In lieu of the wireline cable, for example,another downhole tool can be used to lower the logging tool into thewellbore and pull the logging tool out of the wellbore. The data isusually collected in a spatially-corrected fashion to increase theamount of true signal over the background noise. In order to make iteasier to use, the data is typically also sampled at a particularsampling rate.

Well logging tools have been around for decades. For example, when welllogging first began in the early 1900's, only spontaneous or ionicpotential and resistivity data was recorded. Today, there are manydifferent types of logging tool configurations available. Examplesinclude spontaneous potential logging tools, resistivity/conductivitylogging tools, image logging tools, acoustic logging tools anddensity/neutron logging tools. Most of the available logging tools arelimited to use in an open-hole environment, although certain types ofresistivity/conductivity logging tools and density/neutron tools can beused in both an open hole and a cased hole environment. The type of datacollected and the manner in which it is collected varies from tool totool.

An example of a modern logging tool is an image logging tool. An imagelogging tool is used to produce “images” of the borehole wall and thesurrounding geologic units penetrated by the wellbore. For example, animage logging tool can be used to identify the dip and azimuth of thegeologic units around the wellbore, locate rock breakouts within theborehole, identify fractures in the surrounding geologic units anddetermine the composition of the surrounding geologic units. Based onthe data collected, a useful well image log can be created thatrepresents the surface of the surrounding geologic units in thewellbore.

There are many factors that can alter the quality of the data collectedand recorded by an image logging tool, including the logging speed, thesampling rate, the rate of turning or spiraling of the logging tool inthe hole, the borehole contact with the sensors, the proximity of thesensors to the rock surface, the borehole internal diameter, theborehole shape or rugosity, the borehole inclination, the radialarrangement of the sensors, the number and orientation of the sensors,and the sensitivity of the sensors. For example, the logging speed,sampling rate and orientation at which data is collected can beparticularly important factors. Based on the dip and azimuth of thewellbore and the surrounding rock, it may be determined, for example,that the final location to which the wellbore is drilled needs to bechanged and that the current wellbore needs to be re-drilled, or eventhat an additional wellbore needs to be drilled from a differentlocation on the site in order to effectively and efficiently penetratethe most promising geologic unit(s).

Well logging tools, including image logging tools, can be classified inmany ways, including but not limited to active vs. passive, pad vs.non-pad, statistical vs. non-statistical, and centered vs. offset oreccentric. For example, an active well logging tool emits a signal (forexample, nuclear radiation, energy waves or high energy particles) intothe wellbore and the surrounding geologic units in order to induce areturn signal that can be received and recorded by the same tool forlater processing into useful data. A passive well logging tool, on theother hand, merely receives emitted signals that contain the usefulinformation from the geologic units penetrated by the wellbore. Apassive well logging tool does not emit a signal into the wellbore orgeologic units.

The types of image logging tools in use today include micro-resistivitylogging tools, acoustic logging tools, and optical logging tools. All ofthese tools are suitable for use in an open-hole environment. Amicro-resistivity image tool is an active, non-statistical image loggingtool that measures the conductivity/resistivity of rock minerals,fluids, gases and other materials in a geologic unit. An acoustic imagelogging tool is an active, non-statistical image logging tool that usessonic waves that reflect off rock, fluid and other material surfaces. Anoptical image logging tool is an active, non-statistical image loggingtool that uses cameras to image the rock, fluid and other materialsurfaces. Micro-resistivity image logging tools are the most common andwidespread image logging tool in use today. All the major loggingvendors have at least one micro-resistivity imager in their portfolio.

A micro-resistivity image logging tool uses a signal transmitter to emita measured amount of electrical current through the borehole wall intothe geologic units surrounding the wellbore. Multiple signaltransmitters positioned around the tool to cover the entire areasurrounding the wellbore are typically used. The current emitted by eachsignal transmitter is altered by the conductivity/resistivity of therock minerals, fluids, gases and other materials that are adjacent tothe wellbore. The altered current is then received by a correspondingreturn signal sensor attached to the logging tool. For example, thesignal transmitters and return signal sensors can be placed in pads thatare forced against the rock wall by extendable offset arms.

The time and distance interval between the emission of the current byeach signal transmitter and the receipt of the altered current by thecorresponding return signal sensor together with the properties of thereturn signals such as their amplitudes and/or phases can be used todetermine the conductivity/resistivity of the materials in the geologicunits, that is, the ability of the materials to resist electricalcurrents. The resulting formation micro-resistivity can be recorded, forexample, as a function of the tool's depth or position in the wellbore.This data is then later processed to create a micro-resistivity wellimage log showing different properties of the geologic units surroundingthe wellbore.

For example, the recorded resistivity of the rock and other materials inthe geologic units can be used to determine the nature of the rock andother materials. For example, the resistivity of shale is different thanthe resistivity of sand, and hydrocarbons and water will also impact thesignal and resulting data. The resistivity data can be very valuable inthe search for hydrocarbons and can dictate how the drilling and/orcompletion programs move forward.

A very important component of any image logging tool is the spatialcontrol of where the transmitters and signals are oriented in xyz spacerelative to the wellbore and the Earth. As used herein and in theappended claims, the “Earth” means the planet Earth. Over the lastseveral decades, tremendous advances have been made in this area withthe use of gyroscopes mounted inside the logging tool. Gyroscopes allowthe data to be corrected in xyz space relative to the wellbore and theEarth to greatly improve the data quality. The corrected data allows animage of the wellbore and the surrounding geologic units to be producedthat can be “unwrapped” to create a two dimensional or three dimensionalview of the inside of the wellbore. Such a well image log can provideinformation regarding, for example, the formation lithology, the natureof the bedding, the content of fluid in the formation, and the dip andazimuth of the surrounding rock. The ability to view processed data intwo-dimensional or three-dimensional space reduces the impact of poordata collection or processing errors due to faulty receivers, holewashouts, excessive tool spinning, insufficient receivers, poor samplingor high logging speeds. Thus, the quality of the final well image log issignificantly enhanced.

The ultimate goal of any image logging tool is to get an accuraterepresentation of characteristics of the geologic units surrounding thewellbore. One measure of the quality of the representation that can beobtained is the signal-to-noise ratio (the “S/N ratio”) associated withuse of the tool. Both the rock being penetrated and the logging toolused to record the data create noise, most of which is random and cannotbe easily eliminated. Reducing the noise and maximizing the signalstrength associated with any well logging tool is a primary objective inthe design and use of the tool. Maximizing the S/N ratio of an imagelogging tool will also improve the final product.

The S/N ratio associated with an image logging tool can be increased,for example, by decreasing the logging speed, using an eccentric, offsetor off-center arrangement of transmitter/sensor pads, moving thetransmitter/sensor pads closer to the wellbore wall, increasing thenumber of signal transmitters and corresponding signal sensors attachedto the logging tool, acquiring data in more accurate three-dimensionalxyz space, and then later processing the data better inthree-dimensional xyz space.

Due to the low S/N ratio associated with cased wellbores,micro-resistivity, acoustic and optical image logging tools aretypically only effective in an open-hole (non-cased) wellbore. Forexample, when a metal casing has been cemented in the wellbore, themetal in the casing interferes with the electrical, acoustic or opticalsignals being sent and received by the tool. The highly conductivenature of the metal casing creates “noise” that can overwhelm both thetool and the rock signal to and from the tool. A solid casing of anytype can make optical image logging tools worthless in looking atgeologic or engineering features in the surrounding formation. Forexample, solid plastic and composite casings are opaque in nature whichcan negatively impact the performance of optical image logging tools.Optical image logging tools are also negatively impacted by opaque orotherwise dirty drilling fluids, even in open holes.

Drilling rigs are very expensive to own, rent and operate. When a wellis being drilled or a drilling rig is otherwise in place, time is money.As a result, a great deal of effort is made to keep the drilling andcompletion process moving forward in a timely and cost-effectivefashion. However, many problems can come up that slow the process andcost the operator time and money. For example, getting a logging toolstuck in an open wellbore before casing has been run can be very timeconsuming and otherwise counterproductive. For example, logging toolsare often “fished out” of the wellbore by specialized subcontractors whoare brought out to the well site on a rush basis. Fishing a stucklogging tool out of the wellbore can take several days of rig andsubcontractor time to accomplish. A stuck logging tool of the type thatcontains an active radioactive source can activate regulatoryrequirements that the well be abandoned and filled with red cement (thered cement warns subsequent well drillers to stay away from the buriedactive radioactive source).

Depending upon the regulatory environment associated with the well, mostcompleted oil and gas wells are ultimately cased (typically with a metalcasing). As a result, electrical, acoustic and optic-based image loggingtools are only useful before the casing is installed.

The nature of an open-hole environment can also negatively impact theperformance of an image logging tool. For example, excessive mud-cakebuildup on the borehole wall can interfere with the signals beingtransmitted and received by an image logging tool. For example, apermeable rock zone that absorbs drilling fluid may result in a thickermud-cake buildup than an adjacent low permeability zone. Also, thenature of the drilling fluid in the wellbore of an uncased hole caninterfere with the signals being transmitted and received by an imagelogging tool. For example, highly resistive or conductive drilling mud,including commonly used oil-based muds, can be problematic formicro-resistivity image logging tools. Logging in an oil-based mud holewith a micro-resistivity image logging tool can require more complexdata collection and processing.

Also, due to the fact that micro-resistivity, acoustic and optical imagewell logging tools can only be used to evaluate the geology inunprotected open-hole environments, the tools are typically designed tobe pulled out of the hole by a wireline cable at a relatively highlogging speed, for example, at a logging speed of at least 1000 feet perhour (“FPH”), usually at about 1800 FPH, and sometimes up to 3600 FPH.When a well is being drilled, it is always important to get the wellcased and otherwise completed as soon as possible. This is due primarilyto the daily cost of having a drilling rig in place (even if thedrilling phase is complete, the drilling rig is still often used tocomplete the well). Also, in many wells, it is important to case thewellbore or one or more portions thereof quickly due to changing wellconditions. For example, in some cases, the wellbore wall is sloughingor the stability of the geologic units around the wellbore is otherwisedecreasing with time. In order to prevent the wellbore from collapsingor caving in, a well operator may decide that casing needs to be put inplace sooner as opposed to later.

Also, in an open-hole environment, the likelihood that changingpressures, changing borehole shapes and other conditions will cause animage logging tool to get stuck increases significantly at slowerlogging speeds. This problem is exacerbated by the outwardly biasingextendable arms and corresponding pads of modern micro-resistivity imagelogging tools which make it easier for such tools to get hung up on therock wall, for example, due to deviations (“doglegs”) in the inclinationof the borehole. As a result, wireline logging engineers operating inopen-hole environments are typically encouraged to use logging speeds ofat least 1000 FPH and preferably 1,800 FPH.

Unfortunately, for a given image logging tool in a given wellboreenvironment, the quality of the logging data decreases as the loggingspeed at which the tool is run increases. A faster logging speed means alower S/N ratio and less collected data. Less collected data means alower quality final image log. In order to accommodate faster loggingspeeds and maximize image quality, image logging tool designers andmanufacturers have increased the sophistication of the tools, includingthe number of pads and sensors on the tools, which allows a highersampling rate to be used. Although this addresses the problem with lowS/N ratios, it also significantly increases the cost of the tools. Forexample, a sophisticated micro-resistivity image logging tool can costover $500,000 today.

The high cost of sophisticated modern image logging tools also createsproblems in and of itself. For example, due to their high cost,micro-resistivity image logging tools are not widely available and canbe in limited local supply. As a result, such tools may not be availableto wireline logging engineers for use in a timely manner on a well. Forexample, additional planning and transportation costs may be incurred ifthe only available micro-resistivity image tool is located in anotherstate.

The increased sophistication and capability of modern micro-resistivityimage logging tools is not always needed. For example, in some cases,the well operator only needs or desires geologic unit dip and azimuthdata. If this is the case, modern micro-resistivity image logging toolsare used in a “dumbed-down” mode. In other words, the same expensivemicro-resistivity image logging tool is run in the same deterioratingdown-hole environment and records the same data, but only part of thedata is processed and presented. This is very wasteful of the dataacquisition time and costs, particularly in view of the risk of placingsuch an expensive tool into poor wellbore conditions and thereby riskingthe tool being stuck.

SUMMARY

In one aspect, a method of creating a well image log of a cased well isdisclosed herein. The method comprises providing a passive cased wellimage logging tool assembly, and moving the logging tool assemblythrough at least a portion of the wellbore at a logging speed of nogreater than 750 feet per hour. The logging tool assembly includes alogging tool body, a plurality of gamma ray radiation sensors attachedto the logging tool body, each gamma ray radiation sensor being capableof continuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to the wellbore as the loggingtool assembly is moved through the wellbore, and at least one spatialpositioning device attached to the logging tool body that is capable ofcontinuously collecting sensor position data reflecting the xyz spatialposition of the gamma ray radiation sensors in the wellbore relative tothe wellbore and the Earth as the logging tool assembly is moved throughthe wellbore. The method further comprises: as the logging tool assemblyis being moved through the wellbore, using the gamma ray radiationsensors to continuously collect gamma ray radiation data that is emittedby the geologic unit(s); as the logging tool assembly is being movedthrough the wellbore, using the spatial positioning device tocontinuously collect sensor position data reflecting the xyz spatialposition of the gamma ray radiation sensors within the wellbore relativeto the wellbore and the Earth; using the collected sensor position datato correct the collected gamma ray radiation data; vertically samplingthe corrected gamma ray radiation data at a vertical distance samplingrate of once every vertical distance sampling interval, wherein thevertical distance sampling interval is no greater than 1.75 inches; andpreparing a well image log based on the sampled gamma ray radiationdata.

In another aspect, passive cased well image logging tool assembly foruse in a cased well is disclosed herein. The passive cased well imagelogging tool assembly comprises: a logging tool body; a plurality ofgamma ray radiation sensors attached to the logging tool body, eachgamma ray radiation sensor being capable of continuously collectinggamma ray radiation data from one or more geologic units surrounding oradjacent to the wellbore as the logging tool assembly is moved throughthe wellbore; and at least one spatial positioning device attached tothe logging tool body that is capable of continuously collecting sensorposition data reflecting the xyz spatial position of the gamma rayradiation sensors in the wellbore relative to the wellbore and the Earthas the logging tool assembly is moved through the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings included with this application illustrate certain aspectsof the embodiments described herein. However, the drawings should not beviewed as exclusive embodiments. The subject matter disclosed is capableof considerable modifications, alterations, combinations, andequivalents in form and function, as will occur to those skilled in theart with the benefit of this disclosure.

FIG. 1 is a perspective view of one embodiment of the passive cased wellimage logging tool assembly disclosed herein, showing the tool in aretracted position in a wellbore.

FIG. 2 is a perspective view of the embodiment of the passive cased wellimage logging tool assembly shown by FIG. 1, showing the tool in anexpanded position in a wellbore.

FIG. 3 is an enlarged, front elevation view of one embodiment of a padassembly of the passive cased well image logging tool assembly shown byFIGS. 1 and 2, illustrating the pad assembly in more detail.

FIG. 4 is an enlarged, front elevation view of another embodiment of apad assembly of the passive cased well image logging tool assembly shownby FIGS. 1 and 2, illustrating the pad assembly in more detail.

FIG. 5 is a schematic view illustrating use of the passive cased wellimage logging tool assembly shown by FIGS. 1 and 2 in association withone embodiment of the method disclosed herein.

FIG. 6A is an enlarged, detail view of a portion of FIG. 5 showing thepassive cased well image logging tool assembly in a retracted positionin the wellbore.

FIG. 6B is an enlarged, detail view of a portion of FIG. 5 showing thepassive cased well image logging tool assembly in an expanded positionin the wellbore.

FIG. 6C is a cross-sectional view taken along the lines 6C-6C of FIG.6A.

FIG. 6D is a cross-sectional view taken along the lines 6D-6D of FIG.6B.

FIG. 7 is an example of a well log that can be generated using themethod and passive cased well image logging tool assembly disclosedherein.

FIG. 8 is a graph illustrating the impact that the distance between theradiation sensors of the passive cased well image logging tool assemblydisclosed herein and the borehole wall (e.g., the rock wall) adjacent tothe outside surface of the casing has on the signal strength of thegamma ray radiation data collected by the tool assembly.

FIG. 9 is a graph illustrating the impact of the logging speed on thecounting time associated with a given well image logging tool assembly.

FIG. 10 is a graph illustrating an example of the likely minimumsampling rate possible in connection with a given well image loggingtool assembly at various logging speeds.

DETAILED DESCRIPTION

The present disclosure may be understood more readily by reference tothis detailed description. Numerous specific details are set forth inorder to provide a thorough understanding of the various embodimentsdescribed herein. However, it will be understood by those of ordinaryskill in the art that the embodiments described herein can be practicedwithout these specific details. In other instances, methods, proceduresand components have not been described in detail so as not to obscurethe related relevant feature being described. Also, the description isnot to be considered as limiting the scope of the embodiments describedherein.

In one aspect, this disclosure provides a method of creating a wellimage log of a cased well. In another aspect, this disclosure provides apassive cased well image logging tool assembly for use in a cased well.For example, the passive cased well image logging tool assemblydisclosed herein can be the passive cased well image logging toolassembly used in the method of creating a well image log of a cased welldisclosed herein.

In one embodiment, the method of creating a well image log of a casedwell disclosed herein comprises:

-   -   a. providing a passive cased well image logging tool assembly,        the logging tool assembly including:        -   a logging tool body;        -   a plurality of gamma ray radiation sensors attached to the            logging tool body, each gamma ray radiation sensor being            capable of continuously collecting gamma ray radiation data            from one or more geologic units surrounding or adjacent to            the wellbore as the logging tool assembly is moved through            the wellbore; and        -   at least one spatial positioning device attached to the            logging tool body that is capable of continuously collecting            sensor position data reflecting the xyz spatial position of            the gamma ray radiation sensors in the wellbore relative to            the wellbore and the Earth as the logging tool assembly is            moved through the wellbore;    -   b. moving the logging tool assembly through at least a portion        of the wellbore at a logging speed of no greater than 750 feet        per hour;    -   c. as the logging tool assembly is being moved through the        wellbore, using the gamma ray radiation sensors to continuously        collect gamma ray radiation data that is emitted by the geologic        unit(s);    -   d. as the logging tool assembly is being moved through the        wellbore, using the spatial positioning device to continuously        collect sensor position data reflecting the xyz spatial position        of the gamma ray radiation sensors within the wellbore relative        to the wellbore and the Earth;    -   e. using the collected sensor position data to correct the        collected gamma ray radiation data;    -   f. vertically sampling the corrected gamma ray radiation data at        a sampling rate of once every sampling interval, wherein the        sampling interval is no greater than 1.75 inches; and    -   g. preparing a well image log based on the sampled gamma ray        radiation data.

As used herein and in the appended claims, a “well” means a drilledwellbore and the geologic units surrounding or adjacent to the wellbore.The terms “wellbore” and “borehole” are used interchangeably and meanthe same thing. A “cased well” means a well in which the wellbore or asection thereof contains an annular casing (for example, an annularmetal casing). A “well image log” means a well log including an image ofall or a portion of a borehole wall and all or a portion of one or moregeologic units surrounding or adjacent to the wellbore. The well imagelog can be used to create a separate dipmeter log.

For example, the passive cased well image logging tool assembly used inthe method disclosed herein can be the passive cased well image loggingtool assembly disclosed herein and further described below. As usedherein and in the appended claims, a “passive” cased well image loggingtool assembly means a cased well image logging tool assembly thatcollects data from one or more geologic units surrounding or adjacent toa wellbore but does not transmit data into the wellbore or the geologicunit(s). Unless stated otherwise, one element “attached to” anotherelement means the one element is directly or indirectly attached to, orincorporated into, the other element.

As used herein and in the appended claims, “collecting” data meansreceiving the data and transmitting the received data to anothercomponent. Receiving data, sensing data, and detecting data mean thesame thing and may be used interchangeably herein. For example, theother component can be a signal processing unit, a memory device forstoring data, or a relay. The other component can be located in thelogging tool assembly itself or at another location (for example, on thesurface). For example, “collecting” gamma ray radiation data meansreceiving gamma ray radiation data naturally emitted from a geologicunit surrounding or adjacent to the wellbore, and transmitting thereceived data to another component. For example, gamma ray radiationdata can be transmitted by a gamma ray radiation sensor to a relay inthe logging tool assembly and by the relay to a signal processing uniton the surface. For example, “collecting” sensor position data meansreceiving sensor position data reflecting the xyz spatial position ofthe gamma ray radiation sensors in the wellbore relative to the wellboreand the Earth, and transmitting the received sensor position data toanother component. For example, sensor position data can be transmittedby the spatial positioning device to a relay in the logging toolassembly and by the relay to a signal processing unit on the surface.

For example, the signal processing unit, wherever it is located, canrecord (for example, store) the data and/or process it for further use.For example, the signal processing unit can be or include a centralprocessing unit.

As used herein and in the appended claims, “gamma ray radiation” meansgamma radiation arising from the radioactive decay of atomic nuclei.Gamma ray radiation includes gamma ray radiation that is naturallyemitted from one or more geologic units surrounding or adjacent to thewellbore. Gamma rays consist of high energy protons and have shortwavelengths, for example, less than one-tenth of a nanometer. Gamma rayradiation can be created by various sources including naturallyoccurring rock radioisotopes. Natural gamma rays can vary depending uponthe type of element from which they are emitted. For example, differenttypes of rock and other materials in a geologic unit emit differentamounts and different spectra of natural gamma ray radiation. Examplesof common naturally occurring rock radioisotopes in geologic unitspenetrated by wellbores include natural radioisotopes of uranium (U),potassium (K), and thorium (Th).

Gamma ray radiation is usually expressed in API (American PetroleumInstitute) units or in parts per million (ppm). For example, the totalgamma ray radiation emission from a geologic unit or portion thereoffrom natural radioisotopes of uranium, potassium, and thorium istypically expressed in API units. For standard gamma ray logs, theindividual gamma ray radiation emissions from thorium and uraniumradioisotopes in the geologic unit or portion thereof are typicallyexpressed in parts per million, while the individual gamma ray radiationemission from potassium radioisotopes is typically expressed in terms ofits bulk rock percentage. For example, the total gamma ray emission aswell as the individual gamma ray emissions from thorium, uranium andpotassium radioisotopes in a geologic unit or portion thereof can becollected by the logging tool assembly in accordance with the methoddisclosed herein.

According to an Oilfield Glossary provided by Schlumberger at“www.glossary.oilfield.slb.com” at the time of filing this application,an API unit is defined as:

-   -   “The unit of radioactivity used for natural gamma ray logs. This        unit is based on an artificially radioactive concrete block at        the University of Houston, Tex., USA, that is defined to have a        radioactivity of 200 American Petroleum Institute (API) units.        This was chosen because it was considered to be twice the        radioactivity of a typical shale. The formation is the primary        standard for calibrating gamma ray logs. However, even when        properly calibrated, different gamma ray tools will not        necessarily have identical readings downhole because their        detectors can have different spectral sensitivities. They will        read the same only if the downhole formation contains the same        proportions of thorium, potassium and uranium as the Houston        standard. For example, logging while drilling (LWD) tools have        thicker housings than wireline tools, causing a different        spectral response to the three sources of radioactivity, and        therefore a different total gamma ray reading in some        formations. The nuclear well log calibration facility at the        University of Houston, known as the API pits, was opened in 1959        for the calibration of natural gamma ray and neutron logs. A        facility for calibrating natural gamma ray spectroscopy logs was        added later.”

In connection with the method disclosed herein, the relative changes inthe gamma ray values (in API units) with respect to gamma ray radiationemitted by a geologic unit are most important. The absolute values (inAPI units) of the gamma ray radiation emitted by the geologic units arenot as important.

In the method disclosed herein, naturally occurring gamma ray radiationdata can be analyzed to characterize, for example, rock or sediment inthe geologic unit(s) surrounding or adjacent to the wellbore. As usedherein and in the appended claims, “gamma ray radiation data” means dataregarding one or more properties of gamma rays emitted from one or moregeologic unit(s) surrounding or adjacent to the wellbore. Types of gammaray radiation data that can be collected by the logging tool assembly inaccordance with the method disclosed herein include the total naturalgamma ray radiation emitted from a geologic unit or portion thereof, theindividual energy profiles corresponding to the types of radioisotopeelements (thorium, uranium and potassium) naturally emitting the gammaray radiation and the intensity or magnitude of the gamma ray radiation.For example, the distance between the point of emission of the naturalgamma ray radiation in the geologic unit and the gamma ray radiationsensor of the logging tool assembly that receives the emission can becollected as well. For example, the absolute value of a change in theintensity of the gamma ray radiation emitted from point to point in ageologic unit is as important as the magnitude of that change.

For example, shales usually emit more gamma rays than sands, sandstoneand carbonate rocks because radioactive potassium is a common componentin their clay content. The clay in shales often contains a higher amountof uranium and thorium isotopes. For example, black shale rich inorganic compounds may emit far more gamma rays than clean sand becauseit has a higher uranium content. The following table shows typical gammaray responses for different types of rocks, as expressed in API units:

GAMMA RAY RESPONSE IN DIFFERENT ROCKS AND MINERALS (Expressed in APIunits) Typical Gamma Ray Values Type of Rock or Other Element (APIUnits) Limestone 10-30 Organic-rich shale  70-250 Sandstone 10-60 Salt 2-20 Shale 70-90As used herein and in the appended claims, the term “rock” includesrock, sediment, minerals and other elements in a geologic unit.

The gamma ray radiation data collected by the logging tool assembly inaccordance with the method disclosed herein can be corrected, correlatedand used to create useful well image logs. For example, the ability todifferentiate between the sources of the gamma ray radiation naturallyemitted from one or more geologic units allows spectral gamma ray logsto be created. For example, a spectral gamma ray log can have the totalgamma ray response on the left column, and the separate responses frompotassium, uranium and thorium radioisotopes on the right column. Forexample, the orientation and intensity/magnitude of the gamma rayradiation can be used to determine the nature of the materials in thegeologic unit at each point in the unit from which the radiation ismeasured.

In addition to collecting gamma ray radiation data that is naturallyemitted from one or more geologic units surrounding or adjacent to thewellbore, the well logging tool assembly used in the method disclosedherein can collect gamma ray radiation data emitted by radioactivetracers that have been injected into the wellbore to provide a way toanalyze the placement and flow of fluids and materials in a geologicunit. For example, such gamma ray radiation data can be used todetermine where a frac job has gone or where production is coming fromin a subterranean formation.

As used herein and in the appended claims, a gamma ray radiation sensormeans a receiver, sensor, detector, or other device that is capable ofcollecting gamma ray radiation data that is emitted from a geologic unitsurrounding or adjacent to a wellbore. For example, the gamma rayradiation sensor can be a scintillation detector or counter configuredto measure the number and energy of gamma rays. For example, each sensorcan contain a crystal of a known chemical composition which is “excited”by the impact of electrons and emits photon pulses as a result thereof.The photon pulses can be counted. For example, the photon pulses canpass into a photo-multiplier tube assembly that increases the photoncounts to a standardized magnitude.

As another example, the gamma ray radiation sensors can include crystalsemiconductors formed of crystals having known properties that respondto gamma rays. For example, semiconductors formed of bismuth geraniumcrystals, gadolinium oxyorthosilicate crystals, cerium doped lutetiumoxyorthosilicate crystals, thallium impurity, “Nal(Ti)” doped sodiumiodide crystals, and any combination thereof can be used. Crystalsemiconductors can have better intrinsic energy resolution thanscintillators with respect to gamma ray radiation. For example, thegamma ray radiation sensors can detect gamma rays from isotope tracers,including Scandium 46, Antimony 124, and Iridium 192.

As used herein and in the appended claims, “sensor position data” meansdata that reflects the xyz spatial position of the gamma ray radiationsensors in the wellbore relative to the wellbore and the Earth as thelogging tool assembly is moved through the wellbore. A “spatialpositioning device” means a device that is capable of continuouslycollecting sensor position data. The spatial positioning devicefunctions to orient the gamma ray radiation data collected by the welllogging tool assembly into xyz space relative to the logging tool body.For example, the spatial positioning device can be used to correct thecollected gamma ray radiation data to xyz space relative to the wellboreand the Earth. For example, the spatial positioning device allows forproper spatial xyz placement of the collected data. The correctionprocess significantly improves the quality of the data provided by thelogging tool assembly as well as the quality of the subsequentlyprocessed data.

For example, the spatial positioning device can be a gyroscope. Forexample, one or more gyroscopes can be attached to the logging toolbody. Suitable gyroscopes for use in connection with the logging toolassembly disclosed herein are available from several vendors. Oneexample of a suitable gyroscope device is sold by Scientific Drilling asa Gyro Measurement-While-Drilling (gyroMWD™) system. Another example ofa suitable gyroscope device sold by Scientific Drilling is a “KeeperGyro™.”

In accordance with the method disclosed herein, various additionalcorrections can be made to the gamma ray radiation data to make it moreaccurate. For example, the method disclosed herein can further compriseprocessing the collected gamma ray radiation data to correct the data toaccount for the rugosity of the borehole, the thickness of the casingand optionally other parameters. For example, the rugosity of theborehole and the thickness of the casing and optionally one or moreadditional parameters can also be sensed by the well logging toolassembly disclosed herein or obtained from known data sources and usedby the well logging tool assembly, together with the collected gamma rayradiation data, to correct the gamma ray radiation data.

As used herein and in the appended claims, the “logging speed” at whichthe logging tool assembly is moved through the wellbore (or a portionthereof) means the rate at which the logging tool assembly (includingthe sensors and other components attached thereto) is moved through thewellbore (or a portion thereof) in terms of distance units per timeunits, for example, the number of feet per hour (“FPH”) that the loggingtool is moved through the wellbore. For example, the logging toolassembly can be moved through the wellbore (or a portion thereof) at alogging speed in the range of from about 30 FPH to about 600 FPH. Forexample, the logging tool assembly can be moved through the wellbore (ora portion thereof) at a logging speed in the range of from about 60 FPHto about 300 FPH. For example, the logging tool assembly can be movedthrough the wellbore (or a portion thereof) at a logging speed in therange of from about 120 FPH to about 180 FPH. For example, the loggingtool assembly can be moved through the wellbore (or a portion thereof)at a logging speed in the range of from about 160 FPH to about 170 FPH.For example, the logging tool assembly can be moved through the wellbore(or a portion thereof) at a logging speed of about 165 FPH.

The fact that the wellbore is cased allows a slower logging speed to besafely used. For example, due in large part to the fact that a drillingrig is usually no longer required, the cost of creating the well imagelog in a cased hole environment is significantly lower than it would bein an open hole environment. The ability to run the tool at a slowerlogging speed means a higher sampling rate can be used which means thatmore gamma ray radiation data can be collected with a less complexlogging tool assembly (for example, as compared to modernmicro-resistivity, acoustic or optical image logging tool assemblies).

For example, the corrected gamma ray radiation data can be verticallysampled by the signal processing unit or another component. The signalprocessing unit or other component can be located in the logging toolassembly itself or at another location (for example, as or as part of acentral processing unit on the surface). The corrected gamma rayradiation data can be vertically sampled either as the method is carriedout or at another time.

As used herein and in the appended claims, “vertically sampling” thecorrected gamma ray radiation data means sampling the corrected gammaray radiation data along the longitudinal axis of the wellbore. Asunderstood by those skilled in the art, the longitudinal axis of thewellbore is not necessarily vertical—it can be horizontal or deviated atsome angle between vertical and horizontal, either away from the surfaceor toward the surface. Accordingly, as used in the term “verticalsampling,” the term “vertical” has no meaning other than along thelongitudinal axis of the wellbore. The dimension in which the verticalsampling is carried out can be distance, time or some other dimension.

For example, the dimension in which the vertical sampling is carried outcan be distance. As used herein and in the appended claims, the term“vertical distance sampling rate” means the rate at which samples of thedata are taken with respect to the vertical distance sampling interval.The “vertical distance sampling interval” means the distance that thelogging tool assembly moves through the wellbore for every sample thatis collected. For example, if S represents the continuous stream ofcorrected gamma ray radiation data transmitted by the spatialpositioning device, D represents the vertical distance sampling intervaland the vertical sampling is performed by measuring the value of the Sonce every D inches, then the vertical distance sampling rate, R(d), atwhich the vertical sampling of S is carried out can be represented bythe formula R(d)=1/D. Accordingly, if D is 1.75 inches, then R(d), is0.57. For example, D is no greater than 1.75 inches. For example, D isin the range of from about 0.5 inches to 1.75 inches. For example, D canbe in the range of from about 0.5 inches to about 1 inch.

For example, the dimension in which the vertical sampling is carried outcan be time. As used herein and in the appended claims, the term“vertical time sampling rate” means the rate at which samples of thedata are taken with respect to the vertical time sampling interval. The“vertical time sampling interval” means the time that the logging toolassembly moves through the wellbore for every sample that is collected.For example, if S represents the continuous stream of corrected gammaray radiation data transmitted by the spatial positioning device, Trepresents the vertical time sampling interval and the vertical samplingis performed by measuring the value of the S once every T second, thenthe vertical time sampling rate, T(d), at which the vertical sampling ofS is carried out can be represented by the formula T(d)=1/T.Accordingly, if T is 1.14 seconds, then the time vertical sampling rate,T(d), is 0.88. For example, T can be in the range of from about 0.25seconds to about 20.0 seconds. For example, T can be in the range offrom about 0.5 seconds to about 10.0 seconds. For example, T can be inthe range of from about 0.6 seconds to about 4.0 seconds. For example, Tcan be in the range of from about 0.90 seconds to about 1.30 seconds.For example, T can be about 1.14 seconds.

The specific vertical sampling rate(s) utilized in a given survey,whether expressed in terms of distance, time or some other dimension,will vary depending on the logging speed used, the rock type, thewellbore geometry, the required accuracy and other factors as known tothose skilled in the art with the benefit of this disclosure. Forexample, a statistically significant vertical sampling rate can be used.

The corrected gamma ray radiation data can also be horizontally sampled.Unlike vertical sampling, which collects data at points along orparallel to the longitudinal wellbore axis, horizontal sampling collectsdata at points outwardly and around with respect to the longitudinalwellbore axis (for example, perpendicularly or at some other angle withrespect to the longitudinal wellbore axis). As understood by thoseskilled in the art, the longitudinal axis of the wellbore is notnecessarily vertical—it can be horizontal or deviated at some anglebetween vertical and horizontal, either away from the surface or towardthe surface. Accordingly, as used in the term “horizontal sampling,” theterm “horizontal” has no meaning other than outwardly and around thelongitudinal axis of the wellbore.

Horizontal sampling can be a function of the number of sensors that arearranged around the logging tool assembly and the wellbore casing wall.It will vary depending on the tool configuration and the inside diameterof the casing. It is also impacted by the sensor window size and sensororientation. Both vertical sampling and horizontal sampling are improvedby slowing the logging tool down and increasing the number of sensors.

For example, the counting time associated with each gamma ray radiationsensor attached to the logging tool body can vary depending on thelogging speed. As used herein and in the appended claims, the “countingtime” associated with a gamma ray radiation sensor means the number ofsensing seconds that the sensor uses to create a value. For example, afast logging speed will cause the sensor to move across a portion ofemitting rock in less time than a slower logging speed on the same rock.As a result, the counting time associated with the sensor will be higherwith the slower logging speed.

As the counting time associated with a gamma ray radiation sensorattached to the tool body increases, the number of gamma ray emissionscollected by the sensor also increases (assuming gamma rays are presentat the time). As long as the counting time is the same across thesampling interval (for example, the vertical distance sampling intervalor vertical time sampling interval), then the number of gamma rayemissions collected over that interval by the sensor will be relativelyequal. However, if the logging speed changes across the samplinginterval, then the number of gamma ray emissions collected over thatinterval by the sensor will change (due to the changing counting time asopposed to changing gamma ray emissions).

For example, the counting time associated with each gamma ray radiationsensor attached to the logging tool body is in the range from about 0.40seconds per inch to about 60.00 seconds per inch. For example, thecounting time associated with each gamma ray radiation sensor attachedto the logging tool body is in the range from about 0.50 seconds perinch to about 12.00 seconds per inch. For example, the counting timeassociated with each gamma ray radiation sensor attached to the loggingtool body is in the range from about 1.00 seconds per inch to about 4.00seconds per inch. For example, at a logging speed of 165 FPH, thecounting time associated with each gamma ray radiation sensor attachedto the logging tool body can be about 1.83 seconds per inch.

For example, at least two gamma ray radiation sensors are attached tothe logging tool body. For example, at least three gamma ray radiationsensors are attached to the logging tool body. The only limitation onthe upper end of the number of gamma ray radiation sensors that can beattached to the logging tool body is practicality. For example,potentially over 100 gamma ray radiation sensors can be attached to thelogging tool body. Multiple gamma ray radiation sensors will increasethe S/N ratio associated with the logging tool assembly by improvingboth vertical and horizontal sampling.

For example, a sufficient number of gamma ray radiation sensors areattached to and equally spaced around and along the logging tool body toallow gamma ray radiation data to be collected at sufficient pointsaround the circumference of the wellbore and an image log of an entiregeologic unit surrounding the wellbore to be prepared. For example,eight gamma ray radiation sensors are attached to and equally spacedaround and along the logging tool body. As will be understood by thoseskilled in the art with the benefit of this disclosure, the gamma rayradiation data at points between the sensors can be determined byinterpolation of the data received by the sensors. For example, thegamma ray radiation sensors can be altered, modified, or focused toincrease the S/N ratio allowing for collection of more accuratespatially correct data.

For example, the well image logging tool assembly can be moved throughat least a portion of the wellbore in accordance with the disclosedmethod by lowering or otherwise moving the tool assembly to the bottomof the well, or another point in the wellbore, and then pulling the toolassembly toward the surface of the well. For example, the gamma rayradiation data can be collected from geologic unit(s) surrounding oradjacent to the wellbore as the tool assembly is pulled to the surfaceof the wellbore. For example, a wireline cable can be attached to thetop of the image logging tool assembly and used to lower the toolassembly into the cased well and pull the image logging tool assemblytoward the surface of the well at a pre-determined logging speed. Asanother example, the image logging tool assembly can be attached to acoiled tubing unit and moved through all or a portion of the cased hole.As will be understood by those skilled in the art with the benefit ofthis disclosure, other methods can also be used to move the imagelogging tool assembly through the wellbore as well.

A well image log based on the collected gamma ray radiation data can beprepared by standard methods known to those skilled in the art with thebenefit of this disclosure. The gamma ray radiation data can berecorded, for example, as a function of the logging tool assembly'sdepth and position in the wellbore to create a gamma ray image logshowing different properties of the geologic units.

For example, the method disclosed herein can further comprise creating athree dimensional image of one or more geological units penetrated bythe wellbore based on the sampled gamma ray radiation data. The threedimensional image can be interpreted, for example, to determine the diporientation and bedding azimuth in the geologic unit and/or the natureof the materials in the unit.

For example, an event plane (such as a bed boundary, fracture or fault)crossing the borehole at an angle would generate events at each sensor,and data reflecting these events can be collected at slightly differentdepths in the wellbore. The relative offset, and the radial andazimuthal positions of each sensor can then be used to compute diprelative to the logging tool body position. Increasing the measurementpoints provides the advantage of systematic redundancy, which allows theapplication of statistical error minimization techniques and higher S/Nratios.

Referring now to FIGS. 1 and 2 of the drawings, one embodiment of thepassive cased well image logging tool assembly for use in a cased welldisclosed herein and used in the method disclosed herein, generallydesignated by the reference numeral 10, will be described. The passivecased well image logging tool assembly 10 comprises a logging tool body12, a plurality of gamma ray radiation sensors 14 attached to thelogging tool body, and a spatial positioning device 16 attached to thelogging tool body. Each gamma ray radiation sensor 14 is capable ofcontinuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to a wellbore as the logging toolassembly is moved through the wellbore. The spatial positioning device16 is capable of continuously collecting sensor position data reflectingthe xyz spatial position of the gamma ray radiation sensors in thewellbore relative to the Earth as the logging tool assembly is movedthrough the wellbore.

As shown by FIGS. 1 and 2, the logging tool assembly 10 is positioneddownhole in a wellbore 18 that penetrates a subterranean formation 20.The wellbore 18 includes a borehole 21 that has a diameter 22. A casing23 surrounds the wellbore 18 and borehole 21. A hardened cement sheath24 surrounds the casing 23. For example, the casing 23 can be formed ofmetal.

Three receptor arm subassemblies 26 are attached to the logging toolbody 12. The number of receptor arm subassemblies 26 attached to thelogging tool body 12 can vary from one to more than three, with the onlylimit on the upper end of the range being practicality.

Each receptor arm subassembly 26 includes four extendable arm sets 28attached thereto. Each extendable arm set 28 includes two individualarms 30. The extendable arm sets 28 are equally spaced radially aroundthe logging tool body 12 and equidistantly offset from one another alongthe longitudinal axis 31 of the logging tool body. The number ofextendable arm sets 28 attached to each receptor arm subassembly 26 canalso vary. For example, at least three extendable arm sets 28 can beattached to each receptor arm subassembly 26 and equally spaced radiallyaround and equidistantly offset along the longitudinal axis 31 of thelogging tool body 12. For example, by having at least three extendablearm sets 28 attached to a receptor arm subassembly 26 and equally spacedradially around the logging tool body, the entire 360 degrees around thewellbore can be covered. By equidistantly offsetting the extendable armsets 28 with respect to one another along the longitudinal axis 31 ofthe logging tool body 12, the coverage of the inside of the casing canbe maximized. For example, in order to increase the detail of thecovered area, eight extendable arm sets 28 can be attached to eachreceptor arm subassembly 26 and equally spaced radially around andequidistantly offset along the longitudinal axis 31 of the logging toolbody 12. The number of extendable arm sets 28 attached to each receptorarm subassembly 26 can be the same or different.

Each extendable arm set 28 includes a pad subassembly 32 attachedthereto. Each pad subassembly 32 includes a pad housing 34 having anouter flat face 36. At least one gamma ray radiation sensor 14 isattached to the outer flat face 36 of each pad subassembly 32. Thenumber of pad subassemblies 32 attached to each extendable arm set 28,and/or the number of gamma ray radiation sensors 14 attached to each padsubassembly 32 can also vary. For example, multiple pad subassemblies 32and/or multiple gamma ray radiation sensors 14 can be used. The numberof pad subassemblies 32 attached to each extendable arm set 28 can bethe same or different. Similarly, the number of gamma ray radiationsensors 14 attached to each pad subassembly 32 can be the same ordifferent. Also, the position and orientation of the gamma ray radiationsensors 14 may vary from pad subassembly 32 to pad subassembly 32.

Each receptor arm subassembly 26 is operable to move the extendable armsets 28 and pad subassemblies 32 attached thereto between a retractedposition, as shown by FIG. 1, and an extended position, as shown by FIG.2. In the retracted position, the logging tool assembly 10 can be moreeasily transported and lowered into and pulled out of the wellbore, asnecessary. In the extended position, the pad subassemblies 32 are biasedagainst the inside surface 37 of the casing 23. Specifically, theextendable arm sets 28 thereof are configured to extend from thereceptor arm subassemblies 26 and the logging tool body 12 in a mannerthat places the outer faces 36 of the corresponding pad subassemblies 32into contact with the inside surface 37 of the casing 23.

The extendable arm sets 28 are arranged 90° apart around the loggingtool body 12. If three extendable arm sets 28 are used, they arearranged 120° apart around the logging tool body 12. Similarly, if fiveextendable arm sets 28 are used, they are arranged 72° apart around thelogging tool body 12, and so forth and so on. Each extendable arm set 28and pad subassembly 32 is equidistantly offset from one another alongthe longitudinal axis 31 of the logging tool body 12. Such anarrangement allows for the logging tool body 12 to be centered withinthe borehole 21 and for the corresponding pad subassemblies 32 to bebiased against the inside surface 37 of the casing 23 thereby reducingone source of spatial error with respect to the collected gamma rayradiation data. The fact that each extendable arm set 28 and padsubassembly 32 is equidistantly offset from one another along thelongitudinal axis 31 of the logging tool body 12 allows the coverage ofthe inside of the casing 23 to be maximized. For example, when everysensor 14 operates at a sampling interval of no greater than 1.75inches, with at least three staggered pad subassemblies 32 and sensors14 per extendable arm set 28, and more than one receptor arm subassembly26 per tool, then an even greater decrease in the sample interval can beachieved with an increase in the S/N ratio.

An attachment assembly 40 for allowing the logging tool assembly 10 tobe attached to the end of a cable wireline or coiled tubing, forexample, is positioned at the top of the logging tool body 12. Forexample, as known to those skilled in the art, the attachment assembly40 can have a structure that allows the end of a wireline cable to beattached thereto.

FIG. 3 illustrates one embodiment of a pad subassembly 32 in detail. Atleast one gamma ray radiation sensor 14 is positioned inside the padhousing 34. A radiation shield 41 is attached to the outer flat face 36of the pad housing 34 over the gamma ray radiation sensor(s) therein.The radiation shield 41 includes a window 42 to allow gamma rayradiation to reach the gamma ray radiation sensor(s) 14 in the padhousing 34. The radiation shield 41 reduces the impact of the gamma rayradiation on the gamma ray radiation sensor(s) 14. For example, theradiation shield 41 can be formed of lead, gold, tungsten or similarradiation absorbing materials.

FIG. 4 illustrates another embodiment of a pad subassembly 32 in detail.In this embodiment, the pad subassembly 32 includes four gamma rayradiation sensors 14. Each gamma ray radiation sensor 14 is positionedinside the pad housing 34. A separate radiation shield 41 is attached tothe outer flat face 36 of the pad housing 34 over each gamma rayradiation sensor 14 therein. Each radiation shield 41 includes a window42 therein to allow gamma ray radiation to reach the gamma ray radiationsensors 14 in the pad housing.

For example, as discussed above, the spatial positioning device 16 canbe a gyroscope. If desired, two or more gyroscopes or other spatialpositioning devices 16 can be attached to the logging tool body 12.

A signal processing unit 50 is also attached to the logging tool body12. As discussed above, alternatively, the signal processing unit can bepositioned on the surface or at some other location. An omnidirectionalgamma ray device 52 is also attached to the logging tool body. Theomnidirectional gamma ray device 52 functions to provide a base line foroffset normalization of gamma rays.

The well image logging tool assembly 10 also includes a centralizedgamma ray radiation sensor 54 attached to the logging tool body 12 fordetecting and receiving gamma ray radiation data. The sensor 54 isattached to an outside surface 56 of logging tool body 12. In analternative embodiment (not shown), the sensor 54 can be housed by thelogging tool body 12. If desired, two or more centralized gamma rayradiation sensors 54 can be used. The sensor(s) 54 can be the same typeof sensor that is used as the sensors 14.

Although not shown by the drawings, the logging tool assembly 10 alsoincludes a number of other components including one or more motors andrelated gears, circuits and systems (not shown) necessary to operate thelogging tool assembly between its retracted position and extendedposition and allow the sensors to communicate with the signal processingunit (for example, to allow the sensors to transmit the data theycollect and their position relative to the tool body to the signalprocessing unit), and to otherwise operate the tool as desired.

Referring now to FIG. 5, an example of use of the passive cased wellimage logging tool assembly 10 in accordance with one embodiment of themethod disclosed herein will be generally described. The logging toolassembly 10 is lowered into and pulled out of the wellbore 18 using awireline cable 62 that is operated by a wireline or logging truck 64 ina manner that will be understood by those skilled in the art with thebenefit of this disclosure. The attachment assembly 40 of the loggingtool assembly 10 is attached to an end 66 of the wireline cable 62.

The annular casing 23 is cemented in place in the wellbore 18 to thetotal depth of the wellbore. An annular cement sheath surrounds thecasing 23 (not shown in FIG. 5, but shown in FIGS. 1 and 2). Thewellbore 18 is surrounded by a plurality of geologic units 80. As shown,the geologic units 80 include wet sand zones 80 a, a shale zone 80 b, ahydrocarbon-rich sand zone (pay zone) 80 c, and a silty shale zone 80 d.The geologic units 80 and the wellbore 18 are traversed by a normalfault 82 (a geological event). Motion/fault direction arrows 86illustrate the direction of motion associated with the normal fault 82.

FIGS. 6A-6D further illustrate the logging tool assembly 10 in itsretracted position and expanded position in a wellbore 18. FIGS. 6A and6C show the tool in a retracted position, for example as the tool isbeing lowered to the desired depth in the wellbore 18. FIGS. 6B and 6Dshow the tool in an expanded position, for example as the tool is beingpulled out of the hole at a desired logging speed. For example, once thetool assembly 10 reaches the desired depth in the wellbore 18, theextendable arm sets 28 and pad subassemblies 32 are expanded to bias theouter faces 36 of the pad subassemblies against the inside surface 37 ofthe casing 23. For example, the logging tool assembly 10 can be operatedto move into its expanded position by sending a signal through thewireline cable 62 to the tool assembly 10.

Once the logging tool assembly 10 is in its expanded position, it ispulled out of the wellbore 18 by the wireline truck 64 and wirelinecable 62 at a desired logging speed. While the tool assembly 10 is beingpulled out of the wellbore 18 at the desired logging speed, it collectsgamma ray radiation data using a desired counting time at a desiredsampling rate. The data is corrected using data from the spatialpositioning device 16 and otherwise processed in a manner that will beunderstood by those skilled in the art with the benefit of thisdisclosure. A well image log 90 is then prepared based on the collecteddata.

FIG. 7 is an example of a well image log 90 that can be created usingthe method and passive cased well logging tool assembly disclosedherein. As shown, the well image log 90 provides an unwrapped wellboreimage 92 with interpreted data regarding the intensity of the gamma rayradiation at different points in the geologic units 80. Due to the factthe log 90 provides an “unwrapped view,” what is seen on the 0/360 line94 a is also seen on the 360/0 line 94 b. The image 92 includesstructural axes 96 and several image tracks 100 across the wellbore 18.Increasing the number of pad subassemblies 32 and gamma ray radiationsensors 14 on the logging tool assembly 10 will decrease the blankspaces 102 between the tracks 100. An increase in the internal diameter22 of the borehole 21 will widen the non-image tracks; however, forlarger holes the tool may operate better if it includes additionalextendable arm sets 28, pad subassemblies 32 and/or sensors 14. Thefinal images can be used to interpret geologic events, boundaries,faults, fractures and dip and azimuth.

FIG. 8 is a graph illustrating an example of the impact that thedistance between the gamma ray radiation sensors 14 and the boreholewall 37 has on signal strength of the gamma ray radiation data collectedby the logging tool assembly 10. By placing the sensors 14 against theinside surface 37 of the casing 23 and centering the logging toolassembly 10 in the middle of the casing, the signal strength shouldincrease by at least 3 to 6 times.

FIG. 9 is a graph illustrating an example of how decreasing the loggingspeed of the image logging tool assembly 10 can increase the countingtime of the tool, allowing for more exposure to the gamma ray source andthereby increasing the signal strength and S/N ratio of the gamma rayradiation data that can be collected by the tool. For example, by usinga logging speed of 300 FPH in accordance with the method disclosedherein, which is ⅙ of 1800 FPH (a typical logging speed used heretoforein association with micro-resistivity logging tools), the counting timecan increase from approximately 0.20 seconds per inch to 3 to 4 secondsper inch, an increase in signal recording time of approximately 17times. Compared to the highest recommended logging speed of 3,600 FPH,the proposed method increases the counting time by over 30 times.

FIG. 10 is a graph illustrating an example of the likely minimumsampling interval possible for the logging tool assembly 10 at variouslogging speeds. For example, at a logging speed of 1,800 FPH, a 6 inchsampling interval can be achieved. At a logging speed of 100 FPH to 300FPH in accordance with the method disclosed herein, a lower samplinginterval of 0.5 to 1 inch (and therefore a higher sampling rate) can beachieved.

Thus, by using the passive well image logging tool assembly disclosedherein in accordance with the disclosed method, a highly orientedlogging survey can be conducted to collect useful wellbore and geologicunit data. For example, by combining a low logging speed with theminimum offset produced by multiple radially arranged radiation sensorsbiased against the inner wall of the wellbore casing, and eliminatinginterference by mud filter cake, drilling fluid and other factors thatare present in an open-hole environment, better data can be collected inaccordance with the disclosed method with a higher S/N ratio, whichallows for the acquisition of more useable data resulting in an improvedimage and interpretation.

By detecting and receiving gamma ray radiation data emitted fromgeologic units surrounding or adjacent to the wellbore and using suchdata to generate a well image log, the method disclosed herein has manyadvantages over micro-resistivity, acoustical, optical and other imagelogging methods used heretofore. For example, using naturally-occurringgamma ray radiation data emitted from geologic units to derive theneeded information allows a passive cased well logging tool to be usedin a cased wellbore. Gamma ray radiation data (for example, fromnaturally occurring gamma rays or injected tracer gamma rays) can becollected without emitting any signal from the well logging toolassembly through the wellbore casing into the surrounding geologicunits. As a result, the regulatory issues associated with using anactive-source image logging tool assembly and the tremendous problemsthat can result if such a tool gets stuck (e.g., due to hole rugosity,differential pressure sticking, wellbore deviations or “dog-legs,”and/or other material in the wellbore) can be avoided.

Perhaps most importantly, using naturally occurring gamma ray radiationdata emitted from geologic units penetrated by the wellbore to derivethe needed information allows the method disclosed herein to be carriedout and the image logging tool disclosed herein to be used in connectionwith wellbores that have already been cased, for example, many yearsago. For example, metal, plastic and composite casings do not interferewith naturally occurring gamma ray radiation transmitted from thegeologic units through the wellbore to the image logging tool assemblydisclosed herein. This creates numerous advantages over methods and welllogging tool assemblies that directly measure theconductivity/resistivity or acoustic or optical properties of materialsin the geologic units and therefore cannot be used in a cased well.

The method and image logging tool assembly disclosed herein can be usedto create a well image log in a variety of different applications. Forexample, if a portion of the wellbore must be cased during the processof drilling a well (for example, due to unstable conditions caused by anunconsolidated zone), the well operator can 1) stop drilling, 2) pullthe drilling bit assembly out of the hole, 3) run a “protective” casingstring across the problem zone, 4) use the method and image logging toolassembly disclosed herein to log across that casing string, 5) run thedrilling bit assembly back to the bottom of the newly cased hole, and 6)continue drilling. As another example, the method and image well loggingtool assembly disclosed herein can be used in connection with active andinactive cased wells, and temporarily abandoned cased wells, includingcased wells drilled decades ago and for which a well image log is notavailable. For example, the potential viability of an abandoned well forfurther production or re-drilling using new technology can now beevaluated. Cased wells in use or used in the past as water productionwells and waste disposal wells can also be effectively evaluated.

For example, with the method and cased well image logging tool assemblydisclosed herein, there are no problems due to mud-cake build up on theborehole wall, high formation fluid invasion into the surrounding rockunit, or the type of drilling fluid used in the wellbore. In most cases,because the well has already been cased, the high cost of having adrilling rig in place is not a factor. The fear that the wellbore willcollapse or cave in is not a factor, which allows the data to beselectively collected at more optimal or non-critical times, thusfurther reducing costs and risks. The fear that the well logging toolwill get stuck due to the shape and rugosity of the hole is not afactor. As a result, the needed data can be collected at a relativelyslow logging speed and/or higher sampling rate as compared to thelogging speed and/or sampling rate that is used in connection with othermethods and well logging tools that are typically used in an open-holeenvironment.

In fact, the naturally occurring gamma ray radiation emitted by the rockand other elements in a geologic unit penetrated by the wellbore can bemore accurately collected at a lower logging speed. For example, a gammaray signal event boundary between sand and shale can be more accuratelydefined at a lower logging speed. The ability to collect the needed dataat a relatively slow speed, for example, a speed no greater than 750FPH, allows the data to be collected in accordance with the method andwell logging tool disclosed herein in a manner that provides, forexample, increased bed definition. This can be done without having toequip the well logging tool with a large number of highly sophisticatedsensors and signal processors. As a result, the passive cased well imagelogging tool assembly disclosed herein does not have to be as robust,sophisticated or expensive as other well logging tools that are used inan open-hole environment and must consequently be operated atsignificantly higher logging speeds.

The S/N ratio associated with the method and passive cased well imagelogging tool assembly disclosed herein is significantly improved byusing the tool assembly in a cased hole environment, by decreasing thelogging speed and thereby increasing the sampling rate associated withthe tool assembly. The S/N ratio associated with the method and passivecased well image tool assembly disclosed herein can be further improvedby increasing the number of gamma ray radiation sensors attached to thetool assembly, using one or more gyroscopes to spatially correct thedata collected by the tool assembly, radially aligning radiation sensorsaround the tool assembly to increase the coverage of surroundinggeologic units, positioning the sensors in a more optimal pattern, andbiasing the sensors against the interior surface of the casing by usingextendable arms.

The fact that the method and tool assembly disclosed herein can be usedin a cased well avoids the time constraints and costs associated withhaving a drilling rig in place and the limitations of an unstablewellbore or other conditions. Thus, the method and tool assembly can besafely used at a time when operational costs are less, time is moreavailable and when the wellbore is not in danger of collapsing.

The method and tool assembly disclosed herein can be used to assessolder cased wellbores, including horizontal wells, for possible re-drilland/or recompletion. The method and tool can add value to wells thathave been stimulated by fracturing and/or acidizing techniques byproviding the ability to qualitatively evaluate the stimulation resultsand identify any uncompleted pay zones or potential accumulationsaccessed by re-drilling.

What is claimed is:
 1. A method of creating a well image log of a casedwell having a casing with an inner diameter, comprising: providing apassive cased well image logging tool assembly, said logging toolassembly including: a logging tool body; a plurality of gamma rayradiation sensors attached to said logging tool body within the innerdiameter of the casing, each gamma ray radiation sensor being capable ofcontinuously collecting gamma ray radiation data from one or moregeologic units surrounding or adjacent to the wellbore as said loggingtool assembly is moved through the wellbore, wherein three or more ofthe gamma ray radiation sensors are attached to the logging tool bodyaround a circumference of the tool body at an overlapping verticallocation and two or more of the gamma ray radiation sensors are attachedto the logging tool body at an overlapping radial location; a verticaland radial radiation shield at each radiation sensor that allows gammaray radiation from a vertical and radial angular portion of a geologicunit to reach the sensor and reduces the effect of gamma ray radiationnoise; and at least one spatial positioning device attached to saidlogging tool body that is capable of continuously collecting sensorposition data reflecting the xyz spatial position of said gamma rayradiation sensors in the wellbore relative to the wellbore and the Earthas said logging tool assembly is moved through the wellbore; moving saidlogging tool assembly through at least a portion of the wellbore at alogging speed of no greater than 750 feet per hour; as said logging toolassembly is being moved through the wellbore, using said gamma rayradiation sensors to continuously collect gamma ray radiation data thatis emitted by the one or more geologic units; as said logging toolassembly is being moved through the wellbore, using said spatialpositioning device to continuously collect sensor position datareflecting the xyz spatial position of said gamma ray radiation sensorswithin the wellbore relative to the wellbore and the Earth; using saidcollected sensor position data to correct said collected gamma rayradiation data; vertically sampling said corrected gamma ray radiationdata at a vertical distance sampling rate of once every verticaldistance sampling interval, wherein said vertical distance samplinginterval is no greater than 1.75 inches; interpolating gamma rayradiation data between the radiation sensors; and preparing a well imagelog based on said sampled gamma ray radiation data and interpolatedgamma ray radiation data.
 2. The method of claim 1, wherein said wellimage log is a spectral gamma ray log.
 3. The method of claim 1, whereinsaid spatial positioning device is a gyroscope.
 4. The method of claim1, wherein said gamma ray radiation data that is continuously collectedby said gamma ray radiation sensors is naturally emitted by the geologicunits.
 5. The method of claim 1, wherein said logging tool assembly ismoved through at least a portion of the wellbore at a logging speed inthe range of from about 30 feet per hour to about 600 feet per hour. 6.The method of claim 5, wherein said logging tool assembly is movedthrough at least a portion of the wellbore at a logging speed in therange of from about 60 feet per hour to about 300 feet per hour.
 7. Themethod of claim 1, wherein said vertical distance sampling interval isin the range of about 0.5 inches to about 1.75 inches.
 8. The method ofclaim 7, wherein said vertical distance sampling interval is in therange of about 0.5 inches to about 1 inch.
 9. The method of claim 1,wherein the counting time associated with each gamma ray radiationsensor attached to said logging tool body is in the range of from about0.40 seconds per inch to about 60.00 seconds per inch.
 10. The method ofclaim 1, wherein said gamma ray radiation sensors are attached to andequally spaced around said logging tool body.
 11. The method of claim10, wherein a sufficient number of gamma ray radiation sensors areattached to and equally spaced around and along the logging tool body toallow gamma ray radiation data to be collected at sufficient pointsaround the circumference of the wellbore and an image log of an entiregeologic unit surrounding the wellbore to be prepared.
 12. The method ofclaim 1, wherein said cased well is inactive.
 13. The method of claim12, wherein said cased well is an inactive well for which a well imagelog is not available.
 14. A method of creating a well image log of acased well having a casing with an inner diameter, comprising: providinga passive cased well image logging tool assembly, said logging toolassembly including: a logging tool body; a plurality of gamma rayradiation sensors attached to and equally spaced around said loggingtool body within the inner diameter of the casing, each gamma rayradiation sensor being capable of continuously collecting gamma rayradiation data that is naturally emitted by one or more geologic unitssurrounding or adjacent to the wellbore as said logging tool assembly ismoved through the wellbore, wherein three or more of the gamma rayradiation sensors are attached to the logging tool body around acircumference of the tool body at an overlapping vertical location andtwo or more of the gamma ray radiation sensors are attached to thelogging tool body at an overlapping radial location; a vertical andradial radiation shield at each radiation sensor that allows gamma rayradiation from a vertical and radial angular portion of a geologic unitto reach the sensor and reduces the effect of gamma ray radiation noise;and at least one gyroscope attached to said logging tool body that iscapable of continuously collecting sensor position data reflecting thexyz spatial position of said gamma ray radiation sensors in the wellborerelative to the wellbore and the Earth as said logging tool assembly ismoved through the wellbore; moving said logging tool assembly through atleast a portion of the wellbore at a logging speed of about 30 feet perhour to about 600 feet per hour; as said logging tool assembly is beingmoved through the wellbore, using said gamma ray radiation sensors tocontinuously collect gamma ray radiation data that is emitted by the oneor more geologic units; as said logging tool assembly is being movedthrough the wellbore, using said spatial positioning device tocontinuously collect sensor position data reflecting the xyz spatialposition of said gamma ray radiation sensors within the wellborerelative to the wellbore and the Earth; using said collected sensorposition data to correct said collected gamma ray radiation data;vertically sampling said corrected gamma ray radiation data at avertical distance sampling rate of once every vertical distance samplinginterval, wherein said vertical distance sampling interval in the rangeof about 0.5 inches to about 1.75 inches; interpolating gamma rayradiation data between the radiation sensors; and preparing a well imagelog based on said sampled gamma ray radiation data and interpolatedgamma ray radiation data.
 15. The method of claim 14, wherein said wellimage log is a spectral gamma ray log.
 16. The method of claim 14,wherein said logging tool assembly is moved through at least a portionof the wellbore at a logging speed in the range of from about 60 feetper hour to about 300 feet per hour.
 17. The method of claim 14, whereinsaid vertical distance sampling interval is in the range of about 0.5inches to about 1 inch.
 18. The method of claim 14, wherein the countingtime associated with each gamma ray radiation sensor attached to saidlogging tool body is in the range of from about 0.40 seconds per inch toabout 60.00 seconds per inch.
 19. The method of claim 14, wherein asufficient number of gamma ray radiation sensors are attached to andequally spaced around and along the logging tool body to allow gamma rayradiation data to be collected at sufficient points around thecircumference of the wellbore and an image log of an entire geologicunit surrounding the wellbore to be prepared.
 20. The method of claim14, wherein said cased well is an inactive well for which a well imagelog is not available.